Staggered horizontal well oil recovery process

ABSTRACT

An in situ combustion process entailing the simultaneous production of oil and combustion gases that combines fluid drive, gravity phase segregation and gravity drainage to produce hydrocarbons from a subterranean oil-bearing formation, comprising initially injecting a gas through a pair of horizontal wells placed high in the formation and producing combustion gas and oil through parallel and laterally offset horizontal wells that are placed low in the formation intermediate the pair of horizontal wells placed high in the formation.

FIELD OF THE INVENTION

The present invention relates to an oil recovery process, and moreparticularly to a method of recovering oil from subterranean hydrocarbondeposits using horizontal wells and in situ combustion.

BACKGROUND OF THE INVENTION

There are many oil recovery processes of the prior art employed for theproduction of oil from subterranean reservoirs. Some of these usevertical wells or combine vertical and horizontal wells. Examples ofpattern processes are the inverted 7-spot well pattern that has beenemployed for steam, solvent and combustion-based processes usingvertical wells, and the staggered horizontal well pattern of U.S. Pat.No. 5,273,111 which has been employed (but limited to) a process usingsteam injection.

U.S. Pat. No. 5,626,191 to Toe-to-Heel Air Injection (THAI) discloses arepetitive method whereby the vertical segment of a vertical-horizontalproducer well is subsequently converted to an air injection well, toassist in mobilizing oil for recovery by an adjacent horizontal well,which is subsequently likewise converted into an air injection well, andthe process repeated.

U.S. Pat. No. 6,167,966 employs a water-flooding process employing acombination of vertical and horizontal wells.

U.S. Pat. No. 4,598,770 (Shu et al, 1986) discloses a steam-drivepattern process wherein alternating horizontal injection wells andhorizontal production wells are all placed low in a reservoir. In situcombustion processes are not contemplated.

Joshi in Joshi, S. D., “A Review of Thermal oil Recovery UsingHorizontal wells”, In Situ, 11(2 &3), 211-259 (1987), discloses asteam-based oil recovery process using staggered andvertically-displaced horizontal injection and production wells pattern.A major concern is the high heat loss to the cap rock when steam isinjected at the top of the reservoir.

U.S. Pat. No. 5,273,111 (Brannan et al, 1993) teaches a steam-basedpattern process for the recovery of mobile oil in a petroleum reservoir.A pattern of parallel offset horizontal wells are employed with steaminjectors. The horizontal sections of the injection wells are placed inthe reservoir above the horizontal sections of the production wells,with a horizontal production well drilled into the reservoir at a pointbelow the injection wells, but intermediate said injection wells. Steamis injected on a continuous basis through the upper injection wells,while oil is produced through the lower production wells. Neither insitu combustion nor line drive processes are taught.

U.S. Pat. No. 5,803,171 (McCaffery et al, 1998) teaches an improvementof the Brennan patent wherein cyclic steam stimulation is used toachieve communication between the injector and producer prior to theapplication of continuous steam injection. In situ combustion processesare not mentioned.

U.S. Pat. No. 7,717,175 (Chung et al, 2010) discloses a solvent-basedprocess utilizing horizontal well patterns where parallel wells areplaced alternately higher and lower in a reservoir with the upper wellsused for production of solvent-thinned oil and the lower wells forsolvent injection. Gravity-induced oil-solvent mixing is induced by thecounter-current flow of oil and solvent. The wells are provided withflow control devices to achieve uniform injection and productionprofiles along the wellbores. The devices compensate for pressure dropalong the wellbores which can cause non-uniform distribution of fluidswithin the wellbore and reduce reservoir sweep efficiency. In situcombustion processes are not mentioned.

WO/2009/090477 (Xai et al) discloses an in situ combustion patternprocess wherein a series of vertical wells that are completed at the topare placed between horizontal producing wells that are specificallyabove an aquifer. This arrangement of wells is claimed to be utilizablefor oil production in the presence of an aquifer.

US Patent Application 2010/0326656 (Menard, 2010) discloses a steampattern process entailing the use of alternating horizontal injectionand production wells wherein isolated zones of fluid egress and ingressare created along the respective wellbores in order to achievehomogeneous reservoir sweep. The alternating wellbores may be in thesame vertical plane or alternating between low and high in thereservoir, as in U.S. Pat. No. 5,803,171. Hot vapour is injected in theupper wells (e.g. steam).

As seen from the above patents, steam-based oil recovery processes arecommonly employed to recover heavy oil and bitumen from undergroundformations. For example, steam-assisted-gravity-drainage (SAGD) andcyclic steam injection are used for the recovery of heavy oil and coldbitumen. When the oil is mobile as native oil or is rendered mobile bysome in situ pre-treatment, such as a steam drive process, thethus-mobilized oil can then drain downwardly by gravity and be collectedby a horizontal collector well.

A serious drawback of steam drive processes is the inefficiency ofgenerating steam at the surface because a considerable amount of theheat generated by the fuel is lost without providing useful heat in thereservoir. Roger Butler, in his book “Thermal Recovery of oil andBitumen', p. 415,416, estimates the thermal efficiency at each stage ofthe steam-injection process as follows: steam generator, 75-85%;transmission to the well, 75-95%” flow down the well to the reservoir,80-95%; flow in the reservoir to the condensation front, 25-75%. It isnecessary to keep the reservoir between the injector and the advancingcondensation front at steam temperature so that the major energytransfer can occur from steam condensing at the oil face. In conclusion,50% or more of the fuel energy can be lost before heat arrives at theoil face. The energy costs based on BTU in the reservoir are 2.6-4.4times lower for air injection compared with steam injection. Severalother drawbacks occur with steam-based oil recovery processes: naturalgas may not be available to fire the steam boilers, fresh water may bescarce and clean-up of produced water for recycling to the boilers isexpensive. In summary, steam-based oil recovery processes are thermallyinefficient, expensive and environmentally unfriendly.

Improved efficiency, shortened time on initial return on investment(i.e. quicker initial oil recovery rates to allow more immediate returnon capital invested), and decreased initial capital cost, in variousdegrees, are each areas in the above methods which may be improved.

SUMMARY OF THE INVENTION

The present invention overcomes problems with the prior artsteam-injection method of inter alfa U.S. Pat. No. 5,273,111 (Brannan)wherein reservoir heating is accomplished by the injection of largequantities of steam, typically under high pressure. Such prior artmethod has the drawbacks of needing to provide large and costlysteam-generating equipment at surface, and as noted below is thermallyinefficient in transferring heat to oil within the reservoir in order toachieve the necessary reduction in viscosity to be able to produce oilfrom a viscous oil reservoir.

Thus substantial costs are further incurred in steam recovery methodswhich use steam to heat oil in heating the large quantities of steamneeded, over and above the captical costs of acquiring, shipping, andassembling the necessary steam generating equipment in the form ofboilers, burners, and associated piping.

Moreover, although in situ combustion oil recovery techniques such asthat disclosed in U.S. Pat. No. 5,626,191 are known, such typicallyinvolve a progression of a combustion front perpendicular to and along ahorizontal collector well, which combustion front at any instant istravelling from a point along the horizontal production well.Accordingly, such prior art in situ combustion recovery method does notallow production of oil from within the underground formationsimultaneously along an entire horizontal length of a production well.

Advantageously, the applicant has created a method of recovering oilfrom within an underground formation, which is able to incorporate in aparticular manner in situ combustion for generating heat (and thusunlike U.S. Pat. No. 5,273,111 does not require costly steam-generatingequipment at surface and injection of steam), and which further, unlikeprior art in situ recovery methods such as U.S. Pat. No. 5,626,191, isable to simultaneously utilize in situ heating and importantly attainproduction of oil from within a formation along an entire length of ahorizontal collector well (or wells), and is able to have relativelyhigh initial oil recovery rates.

Specifically, the method of the present invention has beenexperimentally proven, in certain conditions as discussed later herein,to achieve a higher initial oil recovery rate than either the staggeredwell method of oil recovery using steam injection as taught in U.S. Pat.No. 5,273,111 [hereinafter the “staggered steam” method] and whichdisadvantageously need have costly steam generating equipment atsurface], or a “crossed well” method of oil recovery which similarlyuses in-situ combustion, the latter being a non-public method of oilrecovery conceived by the inventor herein and in many respects itself animprovement, in certain respects and to varying degrees, over prior artmethods and configurations.

Specifically, for a comparable volumetric sweep area and identical totalcumulative oil recovery in regard to a subterranean undergroundreservoir (formation), the staggered well (air injection) method of thepresent invention has been experimentally shown, under certainconditions as discussed herein, to provide a greater initial rate ofrecovery of oil than the “staggered steam” method or the “crossed well”method. Thus using the method of the present invention a greater andmore rapid initial return on investment may be achieved.

For oil companies incurring large expenditures in developingsubterranean reservoirs, the ability to utilize a method which willgenerate revenue quickly and thereby permit quicker “pay-down” ofinitial expenses incurred with regard to search, locating, andacquiring, and initially drilling wells in a hydrocarbon-bearingformation is a significant advantage. The time in which a return oninvestment may be realized is frequently a very real and substantialconsideration as to whether the investment in such a capital project isor can ever be made in the first place.

Accordingly, in one broad embodiment of the oil recovery process of thepresent invention, such method comprises a continuous in situ combustionprocess using solely horizontal wells for injection of an oxidizing gasand for the simultaneous production of oil, using a symmetrical array oflaterally and vertically offset (i.e. alternately ‘staggered’) parallelhorizontal injection and production wells.

More particularly, in one broad embodiment of the oil recovery method ofthe present invention such method comprises the steps of:

(i) drilling a pair of parallel, spaced-apart, upper horizontal wellswithin said hydrocarbon-containing reservoir, substantially coplanarwith each other;

(ii) drilling, relatively low in said reservoir, a lower horizontal wellsituated below said upper horizontal wells and positioned substantiallyparallel to and intermediate said pair of upper horizontal wells;

(iii) injecting an oxidizing gas into each of said upper horizontalwells and injecting said oxidizing gas into said reservoir via aperturesin each of said pair of upper horizontal wells;

(iv) igniting said oxidizing gas and hydrocarbons then contained withinsaid formation and causing oil in said formation to become heated;

(v) recovering oil which has become heated and which has migrateddownwardly in said subterranean reservoir, in said lower horizontalwell; and

(vi) recovering said oil from said lower horizontal well to surface.

Such method meets the commercial need of having relatively low energycosts (in that a separate supply of fuel for boilers to generate steamis not needed), and has lower initial capital start-up costs due to lackof need to acquire steam-generating equipment. Moreover, as set outbelow, such novel method for recovering hydrocarbons from a subterraneanformation has a high initial oil recovery rate which is a significantadvantage in allowing income generated from the produced oil to be morequickly applied against the significant expenses of locating, acquiring,and developing a suitable hydrocarbon containing deposit.

In a further preferred method of the present invention, such method maycomprise the further steps of:

(a) drilling a further upper horizontal well within an upper region ofsaid hydrocarbon-containing reservoir substantially parallel to andlaterally spaced apart from said upper horizontal wells;

(b) drilling a further lower horizontal well intermediate said furtherupper horizontal well and a nearest of said previously-drilled upperhorizontal wells, said lower horizontal well positioned below said upperhorizontal wells and positioned substantially parallel therewith;

(c) injecting said oxidizing gas into said further upper horizontal welland into said nearest of said previously-drilled upper horizontal wellsso as to thereby inject said oxidizing gas into said reservoir via aplurality of apertures in both said further upper horizontal well andsaid nearest of said upper horizontal wells;

(d) collecting oil which has become heated as a result of heat beingproduced during combustion of said oxidizing gas and hydrocarbons insaid reservoir and which oil has migrated downwardly in saidsubterranean reservoir, in said further lower horizontal well;

(e) recovering said oil from said further lower horizontal well tosurface.

In a further preferred embodiment, such above method may be used toprogressively recover oil from an underground formation in a “linedrive” manner. Accordingly, in such “line drive” embodiment, above steps(a)-(e) are successively repeated to thereby progress in a lineardirection with drilled horizontal wells so as to progressively recoveroil in said linear direction from said underground hydrocarbonreservoir.

The distance between the parallel lower horizontal wells, the upperhorizontal wells, as well as the respective upper and lower welllengths, will all depend upon specific reservoir properties. Suchdistances can, however, be adequately optimized by a competent reservoirengineer. The lateral spacing between the horizontal wells can be 25-200meters, preferably 50-150 meters and most preferably 75-125 meters. Thelength of the horizontal well segments can be 50-2000 meters, preferably200-1000 meters and most preferably 400-800 meters. The verticaldistance between the upper horizontal injection wells and the lowerhorizontal producer wells is typically dictated by the depth of the oilbearing seam within an underground formation, with such depths typicallyvarying between 2 m to 50 m, but sometimes greater, with the upperhorizontal injection wells being located in an upper region of thehydrocarbon-containing seam within the underground formation, and thelower horizontal production wells located along a lower base of theoil-containing seam within the underground formation.

In each of the above methods it is further contemplated that hotcombustion gases which are produced upon ignition of the hydrocarbonsand oxidizing gas will travel from a high pressure area within theformation (i.e. typically proximate the upper horizontal injector wells)to a low pressure area (i.e. typically proximate the lower producerwells), and be further drawn into and recovered from said lowerhorizontal well along with said oil to surface.

In a homogeneous reservoir using the method of the present invention itis beneficial for high reservoir sweep efficiency to deliver theinjectant equally to perforations in a well liner within the upperhorizontal wells, and to utilize as best as possible equal oil entryrates at each perforation along well liner(s) contained within the lowerhorizontal (production) well. Considering that all horizontal wellstypically have a ‘toe’ at a distal end thereof, and a ‘heel’ at aproximal end thereof where the horizontal well joins thedownwardly-drilled vertical segment of a horizontal-vertical well pair,in a refinement of the present invention the upper horizontal wells aredrilled so that the respective “heels” of the parallel upper horizontal(injection) wells are all on a same side of the reservoir, such sidebeing opposite a side of the reservoir at which the respective heel(proximal end) of the adjacent laterally spaced apart lower horizontalproduction wells is situated. In other words, the vertical wells whichare connected to each of the respective upper horizontal wells are onopposite sides of the reservoir that the vertical wells for thecorresponding lower horizontal wells (and their associated respectiveheel portions) are located. In such manner oxidizing gas which isinjected in the upper horizontal well (the pressure thereof beinghighest at the “heel” [i.e. proximal] end of such upper horizontalwells) has less of a tendency to “short-circuit” directly to the lowpressure portion of the lower horizontal well which is at the heel(proximal) end of such lower horizontal well, then located on theopposite side of the reservoir.

Accordingly, in a further preferred embodiment of the present inventionthe step of injecting said oxidizing gas into said upper injection wellscomprises the step of injecting said oxidizing gas into proximal ends ofsaid upper horizontal wells, such proximal ends situated on a side ofsaid underground formation, and said step of withdrawing oil from saidlower horizontal well comprises withdrawing said oil from a proximal endof said lower horizontal well which is situated on another side of saidreservoir opposite said side at which said proximal ends of said upperhorizontal wells are situated.

In an alternative embodiment which accomplishes the same purpose ofreducing the tendency of “short circuiting” and advantageously allowsboth the injection and production wells to be drilled with theirrespective vertical portions (i.e. proximal ends) situated on the sameside of the reservoir (i.e. a drilling pad for drilling each of theupper and lower wells can thereby remain on the same side of thereservoir and need not be moved back and forth to opposite sides of thereservoir when drilling lower wells and then upper wells), internaltubing may be used in the upper injection wells and/ or the lowerproduction well(s).

Specifically, in an alternative embodiment where tubing is employed inthe upper horizontal wells, such tubing is provided with an open endproximate the distal end of the upper horizontal wells. Such allowstransfer of the point of injection of the oxidizing gas (and thus thehigh pressure point in such upper horizontal well) to the distal endthereof. In such manner the high pressure source in the upper horizontalinjection wells will be at an end of the reservoir opposite the lowpressure toe of the producing wells, thereby forcing heated gas totravel a longer distance through the formation and thereby moreeffectively heat and free oil trapped in the formation, and furtheravoid “short-circuiting” of combustion gases. Heated gases are thuscaused to travel through the formation and be collected by the lowpressure area at the toe of the production well. Such configuration hasthe benefit of permitting drilling pads to all be located on the sameside of the reservoir.

Similarly, where tubing is employed in the lower horizontal wells, suchtubing is provided with an open end proximate the distal end of thelower horizontal wells, with the proximal ends of each of the upperproduction wells, and the lower production well(s) situated on the sameside of the reservoir. Such tubing allows transfer of the point ofrecovery of the produced oil (and thus transfer of the lowest pressurepoint in such lower horizontal well) to the distal end of the lowerproduction well. In such manner the high pressure source in the upperhorizontal injection wells will again be at a proximal end thereof,namely at an end of the reservoir opposite the low pressure distal (toe)portion of the producing wells, thereby forcing heated gas to travel alonger distance through the formation and thereby more effectively heatand thus free oil trapped in the formation, and avoid “short-circuiting”of heated gas. Such configuration, wherein each of the proximal ends ofthe upper injector wells and lower production wells are on the same sideof the reservoir, again has the benefit of permitting all drilling padsto be located on the same side of the reservoir.

As an alternative to the employment of configurations which transpose(reverse) the respective heel and toe portions of adjacent horizontalwells or alternatively use internal tubing in the injector well, theuniform delivery of gas along the length of the injection well anduniform collection in the production well may be obtained, or furtherenhanced, by varying the number and size of perforations along the wellliner in an injector well, to balance the pressure drop along the well.A pressure-drop-correcting perforated tubing can be placed inside theprimary liner. This has the advantage of utilizing gas flow in theannular space to further assist the homogeneous delivery of gas.

Specifically, the number and size of perforations of the well liner in ainjector producer well may progressively increase from the heel portionto the toe portion thereof, in order to more uniformly distribute suchoxidizing gas to the reservoir along the entire length of the upperinjector wells, and assist in preventing “fingering” of injectant gasdirectly into production wells.

Accordingly, in one such embodiment each of said upper horizontalinjector wells has a well liner in which said plurality of apertures aresituated, and wherein a size of said apertures or a number of saidapertures within said well liner progressively increases from a proximalend to a distal end of said upper horizontal wells, and said oxidizinggas is injected into said proximal end of each of said upper horizontalwells.

Alternatively, or in addition, said lower horizontal well may beprovided with a well liner in which a plurality of apertures aresituated, and wherein a size of said apertures or a number of saidapertures within said well liner progressively increases from a proximalend to a distal end of said lower horizontal well, in order to moreuniformly collect mobile oil along substantially the entire length ofthe production well, and to assist in preventing “fingering” ofinjectant gas directly into production wells.

Accordingly, in a further preferred refinement to better allow the upperproduction wells to more uniformly distribute the oxidizing gas to theformation to avoid “fingering” or “short circuiting” of high pressureoxidizing gas directly to production wells, and to further allow moreuniform and efficient collection of oil from the formation by the lowerproduction wells, each of said proximal ends of the upper horizontalinjection wells are situated on the same side of the reservoir as theproximal ends of each of the lower horizontal producer wells, and

(i) each of said upper horizontal injector wells has a well liner inwhich said plurality of apertures are situated, and wherein a size ofsaid apertures or a number of said apertures within said well linerprogressively increases from a proximal end to a distal end of saidupper horizontal wells, and said oxidizing gas is injected into saidproximal end of each of said upper horizontal wells; and

(ii) said lower horizontal well(s) may be provided with a well liner inwhich a plurality of apertures are situated, and wherein a size of saidapertures or a number of said apertures within said well linerprogressively increases from a proximal end to a distal end of saidlower horizontal well.

The outside diameter of the horizontal well liner segments can be 4inches to 12 inches, but preferably 5-10 inches and most preferably 7-9inches. The perforations in the horizontal segments can be slots,wire-wrapped screens, Facsrite™ screen plugs or other technologies thatprovide the desired degree of sand retention.

The injected gas may be any oxidizing gas, including but not limited to,air, oxygen or mixtures thereof. In a preferred embodiment the oxidizinggas is air but is further diluted with a varying quantity anon-oxidizing gas such as carbon dioxide or steam, to thereby reduce(per injected volume) the relative concentration of oxygen in suchquantity of injected gas, thereby allowing control over the temperatureproduced during combustion by decreasing the amount of oxygen allowed tocombust with hydrocarbon within the formation.

Alternatively, or in addition, such oxidizing gas contains water vapour,or water droplets, or water which turns to steam, which condenses whenmoving downwardly in the formation and which releases heat in the latentheat of condensation thereby assisting in transferring heat to oil inthe lower portion of the formation and allowing such oil to becomemobile and drain downwardly into the lower horizontal collector well.

The maximum oxidizing gas injection rate will be limited by the maximumgas injection pressure which must be kept below the rock fracturepressure, and will be affected by the length of the horizontal wells,the reservoir rock permeability, fluid saturations and other factors.

The use of a numerical simulator such as that used in the examples belowis beneficial for confirming the operability and viability of the designof the present invention for a specific reservoir, and can be readilyconducted by reservoir engineers skilled in the art.

BRIEF DESCRIPTION OF THE DRAWINGS

In the accompanying drawings, which illustrate one or more exemplaryembodiments and are not to be construed as limiting the invention tothese depicted embodiments:

FIG. 1 shows a perspective schematic view of a subterraneanhydrocarbon-containing, showing the “staggered well” method of thepresent invention, having a plurality of upper horizontal injectionwells and a plurality of alternatingly-spaced lower horizontalproduction wells situated low in the reservoir, which uses air injectionand in-situ combustion to provide heat to mobilize oil in the formation;

FIG. 2 shows a cross-sectional view of FIG. 1 taken along plane “A-A” inthe direction of arrows “A-A;

FIG. 3 is a perspective view of the staggered well method of the presentinvention, after a “line drive” method is employed;

FIG. 4( i)-(iii) is a series of three cross-sectional view of FIG. 1taken along plane “A-A” in the direction of arrows ‘A-A’, showing aprogression of oil recovery steps during successive time intervalsduring the carrying out of the staggered well “line drive” embodiment ofthe present invention;

FIG. 6 shows a perspective schematic view of an alternative “staggeredwell” method of the present invention, wherein the proximal ends of eachof the upper and lower horizontal wells are located on the same side ofthe underground hydrocarbon reservoir;

FIG. 6 is an enlarged perspective view of various upper and lowerhorizontal wells, showing a manner of employing tubing in each of theupper horizontal wells in accordance with an embodiment of the method ofthe present invention;

FIG. 7 is an enlarged perspective view of various upper and lowerhorizontal wells, showing a manner of employing tubing in the lowerhorizontal well(s) in accordance with an embodiment of the method of thepresent invention;

FIG. 8 is an enlarged perspective view of various upper and lowerhorizontal wells, showing a manner of employing progressively increasingnumber of apertures in each of the well liners of the upper and lowerhorizontal wells, in accordance with a further alternative embodiment ofthe method of the present invention;

FIG. 9 is an enlarged perspective view of various upper and lowerhorizontal wells, showing a manner of employing progressively increasingsizes of apertures in each of the well liners of the upper and lowerhorizontal wells, in accordance with a further alternative embodiment ofthe method of the present invention;

FIG. 10 is an alternative oil recovery method, not part of the presentinvention herein, and is the configuration of the alternative methodused for comparison purposes in comparing relative oil recovery factorof such method to that of the present invention, as shown in FIG. 11;and

FIG. 11 is a graph showing the percentage of oil recovered from aformation, using the method of the present invention (graph “X”); themethod of FIG. 10 (graph “Y”); and a method using staggered wells notforming part of the invention which utilizes steam injection for heatinginstead of oxidizing gas injection and in situ combustion for heating(graph “Z”).

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

FIGS. 1-3 & 5 show a developed subterranean formation/reservoir 22 usingan embodiment of the “staggered well” method of oil recovery of thepresent invention (hereinafter the “Staggered Well” method). In such“Staggered Well” method parallel upper horizontal injection wells 1, 1′,& 1″ of each of length “b” are placed parallel to each other in mutuallyspaced relation, all situated high in a hydrocarbon-containing portion20 of thickness “a” which forms part of subterranean formation/reservoir22 situated below ground-level surface 24. Parallel horizontal, spacedapart lower horizontal production wells 2, 2′ & 2″ of similar length “b”are respectively placed low in the reservoir 22, both below andapproximately intermediate respective injection wells 1, 1′, and 1″, tomake a well pattern array of staggered and laterally separated paralleland alternating horizontal gas injection wells 1, 1′, & 1″ and oilproduction wells 2, 2′ & 2″ as shown in FIGS. 1-3 & 5.

The hydrocarbon-containing reservoir 22 shown in FIG. 1 possesses twoand one-half injection wells 1, 1′, & 1″ and two and one-half productionwells 2, 2′, & 2″ (edge injection well 1 and edge production well 2″each respectively constituting one-half well) for a total of fivehorizontal wells in the pattern. Conducting three repetitions of themethod of FIG. 1 requires fifteen horizontal wells, as shown in FIG. 3.

The lateral spacing “c” of the upper horizontal injection wells 1, 1′, &1″ and the lower horizontal injection wells 2, 2′ & 2″ is preferablyuniform.

In the embodiment of the Staggered Well method shown in FIG. 1, thevertical segments 8 of the horizontal injection wells 1, 1′ & 1″ are atopposite sides of reservoir 22 compared with the vertical segments 9 ofthe horizontal production wells 2, 2′ & 2″, each vertical segment 8 ofassociated respective horizontal well 1, 1′ & 1″ extending upwardly tosurface 24 and likewise each vertical segment 9 of associated respectivehorizontal production well 2, 2′ & 2″ extending upwardly to surface 24.(For purposes of clarity, only vertical segments portions 8, 9 of therespective vertical wells extending to surface 24 are depicted in FIG.1). Accordingly, the vertical segments 8 of the each of injection wells1, 1′, & 1″ in the embodiment of the method shown in FIG. 1 are thuslongitudinally offset by the well length ‘b’ from the respectivevertical segments 9 (and corresponding associated horizontal productionwells 2, 2′ & 2″.

Vertical segments 9 and associated horizontal production wells 2, 2′, &2″ which are situated intermediate horizontal injection wells 1, 1′ &1″, are laterally offset from horizontal injection wells 1, 1′ & 1″ andassociated vertical segments 8 a distance “c”. The reason for suchlateral offset “c” is to eliminate or at least minimize“short-circuiting” of injected oxidizing gas directly from injectionwells 1, 1′, & 1″ into production wells 2, 2′ & 2″ as explained above.

The pattern shown in FIG. 1 can be extended indefinitely away from theface 3 and/or the face 6 as desired to cover a specific volume of oilreservoir 22. In further phases of the reservoir development, as shownin FIG. 3, an additional array of injections wells 1, 1′, & 1″ andproduction wells 2, 2′ & 2″ are drilled adjacent to the first array ofFIG. 1, and such process repeated, eventually exploiting the entirereservoir 22.

Referring to FIG. 1 showing one embodiment of the invention, horizontalinjector wells 1 & 1′ and production well 2 are drilled, in a preferredembodiment each being provided with well liner segments 30 situated ineach of horizontal wells 1, 1′, & 1″ and 2, 2′ & 2″. Well liner segments30 each contain apertures or slots 24 from which an oxidizing gas, whichmay further include carbon dioxide and/or steam, is injected intoformation 22 via an injector wells 1, 1′.

Upon ignition of the so-formed oxidizing gas and hydrocarbon mixture inthe reservoir 22, and in particular in the oil-bearing seam 20 thereof,heated oil and combustion gas (not shown) contained with reservoirpartition segments 50 a, 50 b flow and are drawn downwardly due to lowerpressures toward production well 2, and are drawn into and enterproduction well 2 via apertures 24 therein. Thereafter such collectedoil and combustion gases (not shown) are drawn to surface 24 via gaslift or pump means.

In the case of horizontal production wells 2, 2′ & 2″, well liners 30and the apertures 24 therein may take the form of slotted liners,wire-wrapped screens, FacsRite™ well liners having sand screen plugs, orcombinations thereof, to reduce the flow of sand and other undesirablesubstances such as drill cuttings from within the formation 22 intoproduction wells 2, 2′ & 2″.

The Staggered Well (Air Injection) method may utilize a “line drive”configuration, by drilling another injection well 1″ and a correspondingproduction well 2′, as shown in FIG. 1. Such method is betterillustrated in FIG. 4( i)-(iii), in which three successive phases areimplemented and depicted. In this regard, FIG. 4 shows views on sectionA-A of FIG. 1, at successive respective time intervals (i), & (iii),showing a method of causing a “line drive” of oil recovery in thedirection “Q”, and in particular the remaining portions of oil bearingseam 20 which continue to possess oil and thus illustrates theprogressive recovery of oil from oil bearing seam 20. Specifically, asseen from the first phase [FIG. 4( i)], the injector wells 1, 1′, and1″, and producer well 2 and 2′ are first drilled, and after injection ofoxidizing gas into formation 22 via injection wells 1, 1′ & 1″ andignition of the so-formed mixture of oxidizing gas and hydrocarbons inreservoir 22, production of oil from well 2 and 2′ is commenced, causingdepletion of oil from oil bearing seam 20, as shown in FIG. 4( i).Thereafter in a second phase [FIG. 4( ii)], a further producer well 2″is drilled, and injection and production commenced respectively inregard to injector wells 1, 1′, and production well 2′. In a third phase[FIG. 4( iii)], a fourth injector 1′″ and a fourth producer 2′″ aredrilled, with production ceasing from production well 2, and injectionand production commenced in injection well 1′″ and production well 2′″respectively. The process may be continued indefinitely as shown in FIG.3, until reaching an end of reservoir 22.

Alternatively, as mentioned above, such “Staggered Well (Air Injection)”method may simply consist of simultaneously drilling a set number ofinjector wells (e.g. such as three wells 1, 1′, & 1″) and acorresponding number of producer wells (e.g. such as three wells 2, 2′ &2″), so as to produce the “pattern” of staggered wells of wells 1, 1′, &1″ and 2, 2′ & 2″ shown in FIG. 1, and produce oil from reservoirpartition segments 50 a,b, 50 c,d, and 50 e. Such pattern may berepeated as necessary, as shown in FIG. 3 through well partitionsegments 50 f-50 o, in order to exploit an entire reservoir 22.

FIG. 5 shows an alternate embodiment of the Staggered Well (AirInjection) method of unregistered trademark of Absolute CompletionTechnologies for well liners having sand screens therein the presentinvention, where each of vertical segments 8, 9 of correspondinghorizontal wells 1, 1′, & 1″ and 2, 2′, & 2″ respectively, are drilledon the same side 4 of reservoir 22. Advantageously, as discussed above,such configuration allows a drilling pad for drilling wells 1, 1′, & 1″and 2, 2′, & 2″ to remain on the same side 4 of reservoir 22, thusincreasing the speed and ease by which the wells 1, 1′, & 1″ and 2, 2′,& 2″ may be drilled.

When vertical segments 8,9 of corresponding horizontal wells 1, 1′, & 1″and 2, 2′, & 2″ respectively are drilled on the same side 4 of reservoir22 as shown in FIG. 5, to better and more uniformly inject oxidizing gasinto formation 22 via horizontal wells 1, 1′, & 1″, and/or to moreuniformly collect oil in horizontal wells 2, 2′, & 2″, it is preferredto use tubing 40 in the manner described below.

Specifically, in a first embodiment employing tubing 40, tubing 40 isinserted in upper horizontal injection wells 1′, 1″, 1′″ of FIG. 1 andin all injection wells, if desired. FIG. 6 shows an exemplification ofsuch concept using tubing 40 in two adjacent injection wells 1′, 1″.Such tubing 40 preferentially extends from the heel 43 at the verticalportion 8 of each of wells 1′, 1″ to the toe portion 44 of each of suchwells 1′, 1″. Gaseous air “G” is injected into tubing 40, which air “G”thereafter flows into injection wells 1′, 1″ and thereafter into oilbearing seam 20 of formation 22 via apertures 24 in well liner segments30 as shown in FIG. 6. Heated oil “O” flows into apertures 24 in wellliners 30 of producer well 2′, and is thereafter produced to surface 24(see FIG. 1)

Alternatively, in a second alternative embodiment employing tubing 40,tubing 40 is inserted in lower production wells 2, 2″, 2′″, and 2″″ ofFIG. 1 and in all injection wells, if desired. FIG. 7 shows anexemplification of such concept using tubing 40 in one production well2′. Such tubing 40 preferentially extends from the heel 43 at thevertical portion 9 of production 2′ to the toe portion 44 thereof, asshown in FIG. 7. Oil “O” is withdrawn from toe 44 of production well 2′via tubing 40, such oil “O” entering apertures 24 in well liners 30 inproduction well 2′, and is thereafter produced to surface 24 (see FIG.1).

Alternatively, instead of using tubing 40 within the method of thepresent invention to more uniformly heat the oil in the formation,prevent short-circuiting between injector wells 1, 1′, 1′″, and producerwells 2, 2′, 2″, and 2″, and thereby better collect oil “O” inhorizontal wells 2, 2′, & 2″, it is contemplated that either the numberor size of apertures 24 in well liners 30 in production wells 2, 2′, 2″,be progressively increased from heel 42 to toe 44.

Specifically, FIG. 8 shows one such embodiment being utilized in respectof a single production well 2′, where the number of apertures 24 in wellliners 30 in production wells 2, 2′, 2″, is progressively increased fromheel 42 to toe 44.

FIG. 9 shows another alternative embodiment of such concept beingutilized in respect of a single production well 2′, where the size ofapertures 24 in well liners 30 in production wells 2, 2′, 2″, isprogressively increased from heel 42 to toe 44.

EXAMPLES

Extensive computer simulation of processes for the recovery of mobileoil were undertaken using the STARS™ Thermal Simulator 2010.12 providedby the Computer Modelling Group, Calgary, Alberta, Canada.

The model dimensions used in comparative Examples 1-3 below in number ofgrid blocks were 20×50×20 and the grid block sizes were respectively 5.0m, 5.0 m and 1.0 m, resulting in the same total reservoir volume in eachcase of 500,000 m³ (i.e. 100 m×250 m×20 m).

The modelling reservoir used in each of comparative Examples 1-3 belowcontained bitumen at elevated temperature (54.4°) with high rockpermeability.

In each of comparative Examples 1-3 below, the total number of wellsused for comparative purposes was the same.

Specifically, for the Staggered Well (Air Injection) method, namely amethod of the present invention (Example 1 below), a total of five wellswere employed, namely 2.5 injection wells 1, 1′, and 1″, and 2.5production wells 2, 2′, and 2″, keeping in mind that injection well 1and production well 2″ which appear at the end of grid block 50 a and 50e, respectively, are counted as half-wells.

For the Staggered Steam configuration and method (e.g. as per FIG. 1,but not using air injection or in situ combustion-see Example 2 below),a total of five wells consisting of 2.5 injection wells 1, 1′, and 1″,and 2.5 production wells 2, 2′, and 2″, again keeping in mind thatinjection well 1 and production well 2″ which appear at the end of gridblock 50 a and 50 e, respectively, are counted as half-wells.

With regard to the “crossed-wells” configuration/method as shown in FIG.10 (see Example 3, below), a similar total of five wells were used,namely two (2) injection wells 1′, 1″, and three (3) production wells 2,2′, 2″, and 2′″, again keeping in mind that production well 2 andproduction well 2″″ which each appear at the end of the grid block shownin FIG. 10 are counted as half-wells.

With regard to each comparative model described in Examples 1-3 below,each model received an identical amount of gaseous injection, namely atotal of 50,000 m³/day, with Examples 1 and 3 receiving air injection,and Example 2 receiving gaseous steam injection.

For combustion simulations with air the reactions used:

-   -   1. 1.0 Oil→0.42 Upgrade (C₁₆H₃₄)+1.3375 CH₄+29.6992 Coke    -   2. 1.0 Oil+13.24896 O₂→5.949792 H₂O+6.0 CH₄+9.5 CO₂+0.5        CO/N2+27.3423 Coke    -   3. 1.0 Coke+1.2575 O₂→0.565 H₂O+0.95 CO₂+0.05 CO/N2

In order to improve sweep efficiency, the transmissibility of the oilproduction wells 2, 2′, 2″, and 2′″ was varied monotonically from 1.0 atthe toe to 0.943 at the heel. Practically speaking, as described herein,such diminished transmissibility of the oil along the length of aproduction well 2, 2′, 2″, and/or 2″″ can be accomplished byprogressively decreasing either the aperture 24 size, or number ofapertures 24 of sequential slotted liner segments 30 from toe 44 to heel42 of production wells 2, 2′, 2″, or 2″″ (see for example FIG. 8, FIG.9, respectively).

Additional reservoir properties for each of the reservoirs 22 andcomparative methods of oil extraction modelled in Examples 1-3 belowwere set out in TABLE 1, below:

TABLE 1 Reservoir properties, oil properties and well control. ParameterUnits Value Reservoir Properties Pay thickness m 20 Porosity % 30 Oilsaturation % 80 Water saturation % 20 Gas mole fraction fraction 0.263H. Permeability mD 5000 V. Permeability mD 3400 Reservoir temperature °C. 54.4 Reservoir pressure kPa 3000 Rock compressibility /kPa  3.5E−5Conductivity J/m.d.C  1.5E+5 Rock Heat capacity J/m³-C 2.35E+6 OilProperties Density Kg/m³ 1009 Viscosity, dead oil @ 20 C. cP 77,000Viscosity, in situ cP 1139 Average molecular weight oil AMU 598 Averagemolecular weight AMU 224 Upgrade Oil mole fraction Fraction 0.737Compressibility /kPa 1.06E+3 The wells were controlled using thefollowing parameters: Maximum air injection pressure kPa 7,000Horizontal well length m 500 Producer BHP minimum kPa 2600 Total air orsteam injection rate m³/d 50,000

Example 1 Staggered Well (Air Injection) Method

FIGS. 1 and 4( i)-(iii) depict a method of oil recovery (using airinjection and in situ combustion heating) of the present invention, andin particular depict the method used in Example 1 [Staggered Well (AirInjection)], utilizing a total air injection volume of 50,000 m³/d.

For the Staggered Well (Air Injection) Method as shown in FIGS. 1, 2.5injection wells 1, 1′, and 1″, and 2.5 production wells 2, 2′, and 2′ aspart of grid blocks 50 a-50 e, were all simultaneously drilled, for atotal of five wells. The reservoir thickness ‘a’ was 20 m and the welloffset ‘c’ was 50 m for each grid block 50 a-50 o. Air injection rateswere 10,000 m³/d for well 1 and 20,000 m³/d for each of injectors 1′ and1″, for a total of 50,000 m³/d for the grid block pattern 50 a-50 e.

A summary of results, namely the Oil Recovery Factor over time (1,825days=5 years) for Example 1, is shown in FIG. 11 as line ‘X’.

Example 2 Crossed-Wells Method

FIG. 10 shows an alternative method of oil recovery from a subterraneanreservoir 22, which is not the subject matter of this application but ofanother patent application of the within inventor and commonly assigned(hereinafter the “crossed wells” method).

In the crossed-well method depicted in FIG. 10, injector wells 1, 1′ areperpendicularly disposed to the horizontal collection wells 2, 2′, 2″,and 2′″. Specifically in this crossed-well method, parallel horizontalwell injection wells 1, 1′ are placed high in reservoir 22, and parallelhorizontal production wells 2, 2′, 2″, & 2″ are placed low in reservoir22 perpendicular to injection wells 1, 1′. Horizontal Injection well 1′is located distance ‘q’ (25 m) from the front edge of the model andinjection well 1 is placed distance ‘q’ from the back side of reservoir22, namely with injectors 1, 1′ separated by a distance ‘2 q’. The welllength is “b”. The spacing of the horizontal production wells is “c”,for a total grid block volume of 500,000 m³.

The air injection rate into the upper injection wells 1, 1′ was 50,000m31/d, divided equally between injector wells 1, 1′. Air was injectedcontinuously and oil, water and gas were produced continuously from thelower wells 2, 2′, 2″ & 2″.

A summary of results, namely the Oil Recovery Factor over time (1,825days=5 years) for Example 2, is shown in FIG. 11 as line ‘Y’.

Example 3 Staggered Steam Method

Example 3 (method of FIG. 1, but with hot steam injection instead of airinjection and not employing in situ combustion) is not part of thepresent invention, and is only provided to illustrate the comparativeefficiency with other oil recovery methods (e.g. Example 1 and Example2).

Saturated steam was injected continuously at the rate of 150, 300 and300 m³/d (water equivalent—for a total of 50,000 m³/d gaseousequivalent) into injection wells 1, 1′ and 1″ respectively, whileproduction wells 2, 2′ and 2″ were open to production.

A summary of results of the Staggered Steam method, showing the OilRecovery Factor over time (1,825 days=5 years) for Example 3, is shownin FIG. 11 as line ‘Y’.

COMPARISON AND PROVEN ADVANTAGES

Comparing lines ‘Y’ (Crossed-wells) and line “X” [the present invention,Staggered Wells (Air Injection) it is clear that at any selected timethe oil recovery is higher with the present invention.

Comparing line “Z” (Staggered Steam injection) with line “X” of thepresent invention [Staggered Wells (Air Injection) ] the benefit ofhigher early oil rate with the present invention is even greater.

The higher Oil Recovery Factors at 2.4 years and 5.0 years of thepresent invention (Line “X”) show the significant financial advantage ofthe present invention considering the earlier return on investment inthe form of earlier and greater oil recovery. Also, with a lower Air/Oilratio than the steam injection method (Example 3), the present invention(Example 1) will carry lower air compression costs. Because of thethermal inefficiency of steam processes, the Staggered Steam process isnot competitive.

TABLE 2 Oil recovery Factors and energy requirements. Oil recoveryCumulative factor, % Oil Oil recovery Cumulative Relative Well 2.4-years5-year, km³ factor at Air/Oil energy Arrangement Line (874 days) (1827days) 5-years, % Ratio cost Crossed Wells* “Y” 49.9 93.3 80.0 980 1.0(Example 2 and FIG. 10)* Staggered Steam “Z” 40.7 98.2 82.7 N/A 2.2-4.4Injection* (Example 3 and FIG. 1) Staggered Wells “X” 56.5 98.2 81.2 8661.0 (Air Injection) (Example 1 and FIG. 1) *Does not form part of theinvention claimed herein

The scope of the claims should not be limited by the preferredembodiments set forth in the foregoing examples, but should be given thebroadest interpretation consistent with the description as a whole, andthe claims are not to be limited to the preferred or exemplifiedembodiments of the invention.

1. An in situ combustion method for recovering oil from ahydrocarbon-containing subterranean reservoir, comprising the steps of:(i) drilling a pair of parallel, spaced-apart, upper horizontal wellswithin said hydrocarbon-containing reservoir and within a horizontalplane therein; (ii) drilling, relatively low in said reservoir, a lowerhorizontal well, situated below said upper horizontal wells andpositioned substantially parallel to and intermediate said pair of upperhorizontal wells; (iii) injecting an oxidizing gas into each of saidupper horizontal wells and injecting said oxidizing gas into saidreservoir via apertures in each of said pair of upper horizontal wells;(iv) igniting said oxidizing gas within said formation and causing oilin said formation intermediate said upper horizontal wells to becomeheated; (v) recovering oil which has become heated and which hasmigrated downwardly in said subterranean reservoir, in said lowerhorizontal well; and (vi) recovering said oil from said lower horizontalwell to surface.
 2. A method for recovering oil from ahydrocarbon-containing subterranean reservoir as claimed in claim 1,comprising the further steps of: (a) drilling a further upper horizontalwell within an upper region of said hydrocarbon-containing reservoirsubstantially parallel to and laterally spaced apart from said upperhorizontal wells; (b) drilling a further lower horizontal wellintermediate said further upper horizontal well and a nearest of saidupper horizontal wells, positioned below said upper horizontal wells andpositioned substantially parallel therewith; (c) injecting saidoxidizing gas into said further upper horizontal well and into saidnearest of said upper horizontal wells so as to thereby inject saidoxidizing gas into said reservoir via a plurality of apertures in saidfurther upper horizontal well and said nearest of said upper horizontalwells; (d) collecting oil which has become heated as a result of heatbeing produced during combustion of said oxidizing gas and hydrocarbonsin said reservoir and which has migrated downwardly in said subterraneanreservoir, in said further lower horizontal well; (e) recovering saidoil from said further lower horizontal well to surface.
 3. A method forrecovering oil from a hydrocarbon-containing subterranean reservoir asclaimed in claim 2, comprising the further steps of: (f) successivelyrepeating steps (a)-(e) to thereby progress in a linear direction withdrilled horizontal wells so as to progressively recover oil in saidlinear direction from said underground hydrocarbon reservoir.
 4. Amethod for recovering oil from a hydrocarbon-containing subterraneanreservoir as claimed in claim 1, 2, or 3, wherein hot combustion gasesare further drawn into and recovered to surface from said lowerhorizontal well along with said oil.
 5. A method for recovering oil froma hydrocarbon-containing subterranean reservoir as claimed in claim 1wherein said step of injecting said oxidizing gas into said upperinjection wells comprises the step of injecting said oxidizing gas intoproximal ends of said upper horizontal wells situated on a side of saidunderground formation, and said step of withdrawing oil from said lowerhorizontal well comprises withdrawing said oil from a proximal end ofsaid lower horizontal well which is situated on another side of saidreservoir opposite said side at which said proximal ends of said upperhorizontal wells are situated.
 6. A method for recovering oil from ahydrocarbon-containing subterranean reservoir as claimed in claim 1wherein said step of injecting said oxidizing gas into said upperhorizontal wells comprises the step of injecting said oxidizing gas intoproximal ends of said upper horizontal wells situated on a side of saidunderground formation, and said step of withdrawing oil from said lowerhorizontal well comprises withdrawing said oil from a distal ends ofsaid lower horizontal well situated on another side of said reservoiropposite said side at which said proximal ends of said upper horizontalwells are situated.
 7. A method for recovering oil from ahydrocarbon-containing subterranean reservoir as claimed in claim 6,wherein production tubing is positioned in said lower horizontal welland which tubing has an open end proximate a distal end of said lowerhorizontal well, said step of recovering oil from said lower horizontalwell comprising the step of recovering said oil via said open end ofsaid tubing.
 8. A method for recovering oil from ahydrocarbon-containing subterranean reservoir as claimed in claim 1wherein production tubing is positioned in each of said upper horizontalwells and which tubing has an open end proximate a respective distal endof each of said upper horizontal wells, said step of injecting oxidizinggas into said formation comprising injecting said oxidizing gas intosaid tubing situated in each of said upper horizontal wells and thusinto distal ends thereof, and said step of withdrawing oil from saidlower horizontal well comprises withdrawing said oil from a proximal endof said lower horizontal well which is situated on a same side of saidreservoir on which proximal ends of said upper horizontal wells aresituated.
 9. A method for recovering oil from a hydrocarbon-containingsubterranean reservoir as claimed in claim 1, wherein each of said upperhorizontal wells has a well liner in which said plurality of aperturesare situated, and wherein a size of said apertures or a number of saidapertures within said well liner progressively increases from a proximalend to a distal end of said upper horizontal wells, and said oxidizinggas is injected into said proximal end of each of said upper horizontalwells.
 10. A method for recovering oil from a hydrocarbon-containingsubterranean reservoir as claimed in claim 1, wherein said lowerhorizontal well has a well liner in which a plurality of apertures aresituated, and wherein a size of said apertures or a number of saidapertures within said well liner progressively increases from a proximalend to a distal end of said lower horizontal well, and said oil isrecovered from said proximal end of said lower horizontal well.
 11. Amethod for recovering oil from a hydrocarbon-containing subterraneanreservoir as claimed in claims 9 and
 10. 12. A method for recovering oilfrom a hydrocarbon-containing subterranean reservoir as claimed in claim11, wherein proximal ends of said upper wells and proximal ends of saidlower horizontal wells are situated on a same side of said reservoir.13. A method for recovering oil from a hydrocarbon-containingsubterranean reservoir as claimed in claim 1, wherein a volume of saidoxidizing gas injected into said subterranean reservoir is equal or lessthan a volume of oil recovered from said horizontal wells located low inthe reservoir.
 14. A method of recovering oil from ahydrocarbon-containing subterranean reservoir as claimed in claim 1,wherein said oxidizing gas comprises oxygen or air.
 15. A method ofrecovering oil from a hydrocarbon-containing subterranean reservoir asclaimed in claim 1, wherein said oxidizing gas further comprises water,steam, or carbon dioxide.
 16. A line-drive method for recovering oilfrom a hydrocarbon-containing subterranean reservoir, comprising thesteps of: (i) drilling a pair of parallel, spaced-apart, upperhorizontal wells within an upper region of said hydrocarbon-containingreservoir, substantially coplanar with each other; (ii) drilling,relatively low in said reservoir, a lower horizontal well, situatedbelow said upper horizontal wells and positioned substantially parallelto and intermediate said pair of upper horizontal wells; (iii) injectingan oxidizing gas into each of said upper horizontal wells and injectingsaid oxidizing gas into said reservoir via apertures in each of saidpair of upper horizontal wells; (iv) igniting said oxidizing gas withinsaid formation and causing oil in said formation intermediate said upperhorizontal wells to become heated; (v) recovering oil which has becomeheated and which has migrated downwardly in said subterranean reservoir,in said lower horizontal well and recovering said oil from said lowerhorizontal well to surface. (vi) drilling a further upper horizontalwell within an upper region of said hydrocarbon-containing reservoirsubstantially parallel to and laterally spaced apart from said upperhorizontal wells; (vii) drilling a further lower horizontal wellintermediate said further upper horizontal well and a nearest of saidupper horizontal wells, positioned below said upper horizontal wells andpositioned substantially parallel therewith; (viii) injecting saidoxidizing gas into said further upper horizontal well and into saidnearest of said upper horizontal wells so as to thereby inject saidoxidizing gas into said reservoir via a plurality of apertures in saidfurther upper horizontal well and said nearest of said upper horizontalwells; (ix) collecting oil which has become heated as a result of heatbeing produced during combustion of said oxidizing gas and hydrocarbonsin said reservoir and which has migrated downwardly in said subterraneanreservoir, in said further lower horizontal well; (x) recovering saidoil from said further lower horizontal well to surface; and (xi)successively repeating steps (vi)-(x) to thereby progress in a lineardirection with drilled horizontal wells so as to progressively recoveroil in said linear direction from said underground hydrocarbonreservoir.
 17. A method of recovering oil from a hydrocarbon-containingsubterranean reservoir as claimed in claim 16, wherein said oxidizinggas comprises a mixture of (i) air and steam; (ii) air and suspendedwater droplets; or (iii) air and water vapour.